The present invention discloses a method for the simultaneous reduction of the concentrations of sulfur dioxide, SO2, and nitrogen oxides, NOx, in the products of combustion of a fossil fuel. The method consists of injecting into the combustion gas stream, liquid droplets containing lime or very fine limestone particles dispersed in water and urea or ammonia dissolved in the same water. Said particle dispersion and solution are produced in a supply vessel by continuous mixing of the lime or very fine limestone solids and the urea solids or ammonia liquid in concentrations of up to 30% by weight for the lime or very fine limestone and up to 10% by weight of the urea or ammonia in the water. Under certain conditions, such as preparing the mixtures in large vessel in which the mixture will remain for extended periods of time, it may be desirable to augment the continuous mixing by the addition of a surfactant and/or stabilizer in order to maintain a uniform dispersion of the lime or very fine limestone particles. Injection of this mixture takes place in a furnace in a temperature range from about 1700xc2x0 F. to 2200xc2x0 F., where both the calcination of lime or very fine limestone and the subsequent reaction of calcium oxide with SO2 and the reaction of urea or ammonia molecules with NOx, are effective. Specifically, the method disclosed consists of preferably using air atomized water droplet injectors that are designed to disperse said droplets exclusively in the optimum gas temperature zone at which vaporization of the droplets disperses the lime or very fine limestone particles and the urea or ammonia gas molecules throughout said gas zone where the SO2 and NOx reduction reactions are effective.
Coal is the primary fuel for utility boilers, and to efficiently burn it requires combustion at 3000xc2x0 F. or higher. Very extensive deposits of high sulfur coals that contain fuel bound nitrogen are available in the Eastern half of the United States, and the use of this coal, especially in the mid-Western States is a major source of SO2 and NOx pollution in the Eastern United States.
The combustion of fossil fuels leads to the formation of NOx and SO2, pollutants that lead to smog and acid rain over wide areas far removed from the combustion source, and it is especially a problem in urban environments. There are two sources of NOx, one is primarily formed during the combustion of solid fossil fuels, namely coal. The fuel bound nitrogen whose concentration is generally in the range of 1%, by weight in the coal is the primary source of NOx in coal combustion. Additionally, combustion with oxygen in excess of the amount required for stoichiometric combustion, which is required for all fossil fuels to minimize other pollutants, such as carbon monoxide, results in the formation of thermal NOx. The thermal NOx concentration rises substantially at temperatures above about 3000xc2x0 F.
Several technologies are used to control the emissions of NOx from fossil, and especially from coal, fired boilers. Among these control technologies are: staged combustion in which initial fuel rich-combustion near the fuel injection zone is followed by excess air combustion in the furnace region of the boiler. There are a number of different staged combustion processes and system designs, depending on the boiler design. Another NOx control process is selective catalytic reduction, SCR, in which the relatively cold combustion gas effluent from a boiler of several 100xc2x0 F., is passed over a catalyst coated bed in the presence of ammonia. Another process, generally called selective non-catalytic reduction, SNCR, involves the injection of various chemical compounds, primarily urea or ammonia, with or without various chemical additives, into the combustion gases in the boiler furnace at temperatures at which the NOx to N2 reaction is favored. The method of the present invention falls within the field of SNCR processes. While all these NOx control processes reduce NOx emissions to varying degrees, they all have certain technical and economic disadvantages. For example, staged combustion results in unburned carbon in the fly ash, which represents an energy loss and may make the fly ash unsuitable for recycling. Also in a certain staged combustion design, called low NOx burners, chemical compounds can form that corrode boiler metal tubes. SCR requires costly catalyst structures, and regular catalyst replacement. The present invention utilizes a SNCR method. It incorporates key elements of Zauderer""s prior invention, (U.S. Pat. No. 6,048,510, herein incorporated by reference in its entirety) in that it eliminates some of the technical disadvantages in the prior invention by assuring a simpler and more uniform method of introducing the urea into the hot combustion gases and it shows that urea is preferred to ammonia for this process. These improvements are the result of practicing the art disclosed in the prior invention that came to light during subsequent testing, and that are disclosed in a subsequent invention by Zauderer on NOx control (U.S. Provisional Application No. 60/185,753, herein incorporated by reference in its entirety). Among the latter improvements are means to eliminate the overheating of the droplet injectors that inserted in the nominal 2000xc2x0 F. combustion gas being treated for NOx reduction.
The combustion of these fossil fuels also leads to the formation of SO2, and both pollutants lead to smog and acid rain over wide areas far removed from the combustion source, and it is especially a problem in urban environments. Sulfur is widely present in coal at concentrations ranging from less that 1% to well above 4%, in some oils, and in some natural gases and oils. It reacts with oxygen during the combustion process to form SO2.
The SO2 molecules that are formed during the combustion of a sulfur containing fossil fuel will react with calcium oxide particles dispersed in the combustion gas to form calcium sulfate, CaSO4. The sulfur gas capture reaction is preceded by calcinations of the lime, Ca(OH)2, or very fine limestone, CaCO3, in the hot combustion gases to form a very porous, reactive calcium oxide, CaO, particle. Calcination is essentially complete at temperatures of about 1800xc2x0 F. It is followed by reaction of the CaO particle with the SO2 gas molecules. Depending on the particle size and its residence time at temperatures considerably higher than 2000xc2x0 F., the CaO particle overheats and begins to fuse. This fusing effect closes its porous structure and sharply reduces the effectiveness of the SO2 capture reaction. Furthermore, at temperatures substantially higher than 2000xc2x0 F., the CaSO4 reaction reverses and the sulfur is re-evolved from the particle as a gas. It is, therefore, essential to implement the calcination and sulfur capture reactions at the appropriate temperature. The droplet method disclosed in this invention for introducing SO2 capture reactants results in a most efficient and low cost method of implementing these process steps.
By coincidence the reaction of urea or ammonia vapor molecules with the NOx that converts the latter to nitrogen, N2, occurs under equilibrium conditions that overlap the temperature range of 1700xc2x0 F. to 2200xc2x0 F. at which the reaction of calcined lime or very fine limestone with SO2 molecules is effective. Consequently, both processes can be implemented in the same apparatus. More importantly, the droplet method disclosed in this invention for introducing both NOx and SO2 capture reactants results in a most efficient and low cost method of implementing these processes.
While ammonia is somewhat more effective in reducing NOx, and less costly than urea, ammonia""s toxicity and handling problems, as well as its high vapor pressure which can result in vaporization of the ammonia in the aqueous feed pipe leading to the injector and resulting in an unsteady, fluctuating flow, makes urea the preferred material for the present invention
There are a number of processes for removing SO2 from stack gases. A widely used method in power plants that is very costly and that is generally called wet scrubbing, involves low (less than 500xc2x0 F.) temperature scrubbing of the gas with a calcium oxide content aqueous solution that forms a sludge containing calcium sulfate. While this method removes well over 90% of the SO2 even in high (4% or greater) sulfur coals, the equipment needed for this process is very costly, difficult to maintain and the resultant sludge must be dried in very large sludge ponds prior to disposal. In addition to removing almost all the SO2 from the combustion gas, these low temperature processes convert almost all the calcium oxide to calcium sulfate, resulting in almost 100% utilization of the calcium. Beneficial use of the residual calcium sulfate as a gypsum construction material is hindered by the need to remove contaminants, such as ash from coal combustion. This further adds to the cost.
An alternative and much less costly process is to inject calcium carbonate, CaCO3, or calcium hydroxide (namely, lime), Ca(OH)2, as a fine powder, in the primary combustion zone of the boiler or downstream in the post combustion zone. The calcium carbonate or hydroxide is generally injected as a fine dry powder in either hot gas zones, as opposed to an aqueous lime or limestone mixture with water because lime or limestone has a negligibly small solubility in water. The particles first calcine to calcium oxide, CaO, at temperatures up to about 1800xc2x0 F. This is followed by a heterogeneous CaO reaction with SO2 to form CaSO4. The equilibrium reaction proceeds up to a particle temperature of about 2000xc2x0 F. Above this temperature, the reaction reverses and the CaSO4 dissociates and re-evolves the SO2 as a gas.
Zauderer (U.S. Pat. Nos. 4,624,191 and 4,765,258) has disclosed SO2 capture in the combustion zone of a slagging cyclone combustor, where the mean gas temperature is in the 3000xc2x0 F. range. This is 1000xc2x0 F. above the equilibrium temperature for SO2 capture. However, Zauderer""s reaction takes place under non-equilibrium conditions. This means that the lime or limestone particles enter the combustion zone in the air and fuel injection zone, where they heatup and undergo rapid calcination in periods of the order of 10""s of milliseconds. This results in a very porous particle having an internal surface area that is 100""s to 1000""s time greater than the outer surface area of the particle. The SO2 gas diffuses into this porous CaO particle and reacts to form CaSO4. Due to the short residence times of the calcium oxide particles in the slagging combustor injection zone, the particle temperature in this region is well below the local combustion gas temperature. It is the local particle temperature that determines the reaction rate between CaO and SO2 and its direction, i.e. capture or re-evolution of sulfur dioxide, in the particle.
This non-equilibrium sulfur capture process is not effective in large boilers fired with conventional pulverized coal burners. In that case, when the lime or limestone particles are injected into the burner zone of the large boiler, the particle residence time is so long, namely periods of one or more seconds, that the particles are heated well beyond 2000xc2x0 F. particle temperature at which the non-equilibrium sulfur capture reaction is effective, and they reach the 3000xc2x0 F. combustion gas temperature. This heating causes xe2x80x9cdeadburningxe2x80x9d of the calcium, namely, the pore structure closes and the effective surface area available for the heterogeneous SO2 capture reaction is sharply reduced. Also, the CaO and SO2 reaction proceeds toward dissociation. One solution is to inject the particles in the lower temperature zone higher up in the boiler furnace, where the gas temperature has been reduced to 2000xc2x0 F. and xe2x80x9cdeadburningxe2x80x9d is suppressed. This latter method is suitable for boilers of all sizes. This later process is the one that is utilized in the present invention. For this process to be effective and efficient it is essential to disperse the lime or limestone particles throughout the gas temperature zone at which SO2 capture is effective. This invention discloses a method for accomplishing the SO2 capture effectively.
With the proper conditions, both the equilibrium and non-equilibrium sulfur capture processes yield high SO2 capture. Zauderer has measured SO2 reductions (xe2x80x9cDemonstration of an Advanced Cyclone Coal Combustor, with Internal Sulfur, Nitrogen, and Ash Control for the Conversion of a 23 MMBtu/hr Oil Fired Boiler to Pulverized Coalxe2x80x9d Coal Tech Corp., August 1991, NTIS Documents DE92002587 and DE92002588, also xe2x80x9cStatus of Coal Tech""s Air-Cooled Slagging Combustorxe2x80x9d in Second Annual Clean Coal Technology Conference, September 1993, NTIS Document Conf-9309152), ranging from 50% to over 80% with non-equilibrium injection into the primary combustion zone of a slagging cyclone combustor and with equilibrium injection in the downstream, post-combustion zone of the boiler furnace. However, in both processes, the amount of calcium utilization was low, ranging at best to about 33%. This means that these two processes require large amounts of reagent for utilization with high (more than 2 to 3% by weight) sulfur coal or other fuels such as petroleum coke, which is costly.
An additional drawback of the non-equilibrium SO2 capture reaction is that although the capture reaction most probably takes place in the fuel injection region and air-fuel mixing region of the primary combustion zone, where the gas temperature is lower and where most of the fuel bound sulfur is released from the volatile matter in the fuel, the reacted sulfur bearing particles are then carried into the primary combustion zone where the gas temperature exceeds 3000xc2x0 F. This will re-evolve the sulfur from the calcium sulfate particles as a gas. One solution to this problem in slagging, cyclone combustor is to drive the particles by centrifugal swirl of the combustion gas into the slag lined wall of the cyclone combustor. The particles dissolve in the slag. However, slag has a very low solubility to sulfur and the sulfur will revolve in a matter of a few minutes, unless the slag is continuously drained from the combustor wall. Therefore, this process is very specific to this type of slagging combustor, as disclosed by Zauderer (U.S. Pat. No. 4,765,258). This approach for SO2 emission control is not suitable for boilers fired with conventional pulverized burners.
On the other hand, the injection of lime, or very fine limestone, using the equilibrium process for the reduction of SO2 emissions is suitable for boilers of all sizes that use combustors of any type and that are fired by any sulfur bearing fuel, such as coal, petroleum coke, or high sulfur-heavy oil. This is the method that it is proposed for practicing the present invention. It involves injection into the furnace zone of the boiler, at a location where the combustion gas temperature is favorable for equilibrium sulfur dioxide gas capture reaction by calcium oxide or any other material that reacts with gaseous sulfur compounds, such as sodium compounds. As noted above (xe2x80x9cDemonstration of an Advanced Cyclone Coal Combustor, with Internal Sulfur, Nitrogen, and Ash Control for the Conversion of a 23 MMBtu/hr Oil Fired Boiler to Pulverized Coalxe2x80x9d Coal Tech Corp., August 1991, NTIS Documents DE92002587 and DE92002588, also xe2x80x9cStatus of Coal Tech""s Air-Cooled Slagging Combustorxe2x80x9d in Second Annual Clean Coal Technology Conference, September 1993, NTIS Document Conf-9309152), Zauderer has measured SO2 reductions of up to 80% when injecting dry calcium hydroxide particles into the furnace region of a 20 MMBtu/hour boiler at a location when the combustion gas temperature was in the range of 2000xc2x0 F. However, the calcium utilization was only about 25%, i.e. the Ca/S mol ratio was 4.
The major barrier that must be overcome to achieve efficient reduction of SO2 and NOx is to assure that the two appropriate reagents intercept most if not all of the gas flow being treated. A solution similar to that proposed by Zauderer (U.S. Pat. No. 6,048,510) for nitrogen oxide reduction by urea or ammonia injection in the upper furnace region of a boiler is utilized in practicing the present invention. For the NOx reduction reaction, the gas temperature partially overlaps the range that is necessary to practice the present invention of SO2 reduction. For NOx reduction, an aqueous solution of the reagent, urea or ammonia, is dissolved in water and atomized in a special injector that yields droplets of varying size that are then dispersed in the region where the NOx reduction reaction is effective in a furnace. The droplets vaporize at their surface toward their core. Therefore, the larger droplets penetrate deeper into the combustion gas before vaporization is completed. One can, therefore, design an injector to atomize droplets in a size range that will allow full coverage of the gas zone being treated, as described by Zauderer (U.S. Pat. No. 6,048,510).
This droplet injection method must be modified when adding SO2 reduction because calcium hydroxide, i.e. lime, and very fine limestone have insignificant solubility in water. Injecting lime or very fine limestone as dry particles has several major disadvantages, which most probably accounts for the low calcium utilization with dry injection, as noted above. The mean size of calcium hydroxide particles is under 10 microns. As a result they are entrained in the gas stream being treated within a short distance from the injection point into the boiler and they do not penetrate throughout the gas zone being treated. This is especially the case in medium size (i.e. 100 MMBtu/hour heat input) and larger boilers. Utilization of a high velocity air jet may project them deeper into the gas stream being treated but it does not solve the problem of widely distributing the lime particles in the gas zone being treated. Limestone has a larger mean size in the 10 to 100 micron range. While the larger limestone particles project further into the gas zone, their larger size reduces the diffusion rate of the SO2 gas molecules into their porous interior formed after calcinations of the limestone. It is widely known that limestone is not as effective as lime particles in sulfur capture.
Another problem with dry particle injection in large furnaces, such as utility boilers, is that the particles will calcine in a distance that is negligible small compared to the gas volume being treated. As a result, the probability of xe2x80x9cdeadburningxe2x80x9d, i.e. overheating of the calcined particles with resultant closure of the internal pore structure, is greatly enhanced. The present invention discloses a means whereby the above noted disadvantages are overcome and the reagent for the SO2 reduction is introduced into the furnace in a manner that yields a most efficient result.
Almost all the tests that were conducted to reduce this invention to practice were implemented in a 20 million Btu/hour air cooled, cyclone combustor that contained most of the design features disclosed in Zauderer""s patents (U.S. Pat. Nos. 4,624,191 and 4,765,258), both are specifically incorporated herein by reference in their entireties. The combustor was attached to a 17,500 pound per hour of saturated steam boiler manufactured by the Keeler Boiler Company, Williamsport, Pa. in the early 1970""s. The key modifications to the design disclosed in said patents were to replace the refractory outlet, namely the exit nozzle, with air cooled pipes whose interior was lined with refractory ceramics held in place with metal studs that were welded to the pipes facing the inside of the combustor. This design is similar to that used in said patents for the main combustion chamber. These pipes were an extension of combustor air cooling pipes that lined the downstream section of the combustor and the cooling air was directed into a chamber that separated the combustor from the boiler to which is was attached. This chamber is identified as item 5 in FIG. 1 of this invention. As a result this additional air diluted the combustion gases exiting the main combustion chamber. In case the main combustion gases were fuel rich, this additional air flowing into chamber 5 would complete combustion. However, for the purposes of this invention, the stoichiometry in the primary combustion chamber was always fuel lean and the combustion gases leaving the primary combustion chamber always had an excess of oxygen.
Also, tests to develop the procedures for practicing this invention were conducted in a 50 MW electric output utility boiler.
Finally, it is to be noted that extensive references in the technical literature and patents exist on the injection of calcium based particles into the combustion and high temperature, 2000xc2x0 F. and above, post-combustion zone of the furnace section in a boiler, either as a dry powder or a slurry. However, these references differ widely in the implementation of said process. Some of these differences appear to be minor but they can have major effects of the efficacy or cost of the method specific method or process. By way of example, Ashworth (U.S. Pat. No. 5,967,061) teaches the use of calcium oxide particles either in dry or in a coal water slurry form. However, it differs very significantly from the present invention in that the particles are injected in a combustion gas temperature range above 2400xc2x0 F. Zauderer (U.S. Pat. No. 4,624,191) teaches that this high temperature range is only effective in a non-equilibrium reaction mode with the SO2, and in large furnace, the reaction will reverse when the particle reaches eventual equilibrium with this hot gas temperature. Ashworth also teaches the dispersion of the calcium oxide in a coal-water slurry that is injected into the post-primary combustion zone of a boiler furnace to effect said SO2 reduction. However, in reducing the present invention to practice, it was noted that as lime concentration exceeded 30% of the weight of the limewater mixture, it turned to a nearly solid sludge. Therefore, adding lime to a coal-water mixture, where the coal concentration, according to Ashworth, is from 40% to 65%, will turn the final mixture to sludge after a relatively small addition of lime. Also, Ashworth does not teach the importance of a wide droplet size distribution to disperse the injected particles, or for that matter the coal-water slurry throughout the gas temperature zone being treated.
Zauderer (U.S. Pat. No. 6,048,258) gives other examples how the droplet injection method used in that invention and in the present invention differs from other methods used to effect NOx reductions by the SNCR process.
The present invention discloses a method for the simultaneous reduction of the concentration of sulfur dioxide, SO2, and nitrogen oxides, NOx, in the products of combustion of a fossil fuel. The method consists of injecting liquid water droplets of varying size, containing smaller lime or very fine limestone solid particles uniformly dispersed in water, into the combustion gas stream. Specifically, the method disclosed consists of air atomized water droplet injectors that are inserted in the furnace of a boiler at the outer edge of a gas temperature zone in the range from about 1700xc2x0 F. to 2200xc2x0 F. Here the calcination of the lime or very fine limestone is followed by reaction with the SO2 in the combustion gas to form calcium sulfate particles. The latter can be removed from the stack gas exhaust by a baghouse filter, an electrostatic precipitator, or a wet scrubber. Simultaneously, the vaporization of the urea or ammonia dissolved in these droplets will react with the NOx and convert it to N2. The atomization produces droplets of varying size in a range that assures their vaporization throughout the combustion gas zone being treated. The dimensions of the boiler determine the optimum droplet size distribution. The lime or very fine limestone particles are substantially smaller than the droplets, and their size is minimized to achieve maximum utilization of the calcium in the reaction with sulfur dioxide. The droplet method disclosed in this invention for introducing SO2 and NOx reduction reactants results in a most efficient and low cost method of implementing these processes.
The present invention includes a method of reducing the concentration of sulfur dioxide, SO2, in an effluent gas stream from the combustion of carbonaceous fuel in a boiler or furnace. The steps include: identifying a gas combustion temperature zone within said boiler or furnace which ranges from about 1700xc2x0 F. to 2200xc2x0 F.; injecting an aqueous liquid into contact with an effluent gas stream in said gas combustion temperature zone within said boiler or furnace, said aqueous liquid comprises dispersed reducing agents consisting of solid particles selected from the group consisting of lime or very fine limestone or similar acting SO2 reducing agents, with or without a surfactant and stabilizer chemical agent to aid in the suspension and dispersion of said solid particles in said liquid and said step of injecting being performed with at least one injector, said step of injecting being performed with a nozzle that forms a flat, planar, fan shaped spray pattern which is oriented perpendicular to said effluent gas stream and is off sufficient cross-sectional area to intercept all of the effluent gas flow in said gas combustion temperature zone; and producing droplets of a non-uniform variable size ranging from 10 xcexcm to 1000 xcexcm where a mean and maximum size of said droplets depend on dimensions of said furnace or boiler, said producing step taking place during said injecting step by varying hydraulic and air atomizing pressures in said injector in order to permit distribution and vaporization of different sized droplets at different locations within said combustion temperature zone, and adjusting a position of an injector droplet outlet of said injector within said boiler or furnace based on an outer edge of said gas combustion temperature zone identified in said identifying step, said adjusting step positioning said injector droplet outlet adjacent to said outer edge of said gas temperature zone identified in said identifying step.
The invention also includes a method of reducing the concentration of sulfur dioxide, SO2, in an effluent gas stream from the combustion of carbonaceous fuel in a boiler or furnace, comprising the steps of: identifying a gas combustion temperature zone within said boiler or furnace which ranges from about 1700xc2x0 F. to 2200xc2x0 F.; injecting an aqueous liquid into contact with an effluent gas stream in said gas combustion temperature zone within said boiler or furnace, said aqueous liquid comprises dispersed reducing agents consisting of solid particles selected from the group consisting of lime or very fine limestone, or similar acting SO2 reducing agent, with or without a surfactant and stabilizer chemical agent to aid in the suspension and dispersion of said solid particles in said liquid and said step of injecting being performed with at least one injector, said step of injecting being performed with a nozzle that forms a conical spray pattern which is oriented coaxial with said effluent gas stream and is of sufficient cross-sectional area to intercept all of the effluent gas flow in said gas combustion temperature zone; and producing droplets of a non-uniform variable size ranging from 10 xcexcm to 1000 xcexcm where a mean and maximum size of said droplets depend on dimensions of said furnace or boiler, said producing step taking place during said injecting step by varying hydraulic and air atomizing pressures in said injector in order to permit distribution and vaporization of different sized droplets at different locations within said combustion temperature zone, and adjusting a position of an injector droplet outlet of said injector within said boiler or furnace based on an outer edge of said gas combustion temperature zone identified in said identifying step, said adjusting step positioning said injector droplet outlet adjacent to said outer edge of said gas temperature zone identified in said identifying step.
One or more injectors may have an atomizing air chamber with outlets for said droplets and inlets for liquid and air and each of said one or more injectors are connected to a pressurized aqueous liquid, containing dispersed particles, filled pipe, and a parallel compressed air pipe, were said air pipe and liquid filled pipe are each placed inside and co-axially within a pipe containing water flowing at sufficient rates to prevent boiling at about atmospheric pressure of all said liquids in all the pipes and inside the droplets injector head which is placed in contact with the said hot gas temperatures. The outer water cooling flow pipes may terminate a slight distance upstream of said compressed air and solution dispersed particle filled pipes, thereby allowing the cooling water to exit the outer cooling pipes and cool the rear of the injector head by evaporative cooling, with the balance of the outer cooling water flow entering the furnace being treated and evaporating.
The outer water cooling pipe may be replaced with a high temperature insulating material consisting either of ceramic fiber cloth or ceramic cement coating surrounding the inner air pipe, and with said ceramic material being of sufficient thickness to maintain the inner air flow at a temperature low enough to prevent boiling of the inner liquid in the injector atomizing chamber.
The concentration of said solid particle reducing agent dispersed in the aqueous liquid can be as high as 30% by weight without the addition of surfactants or stabilizers, and where said particles are maintained in uniform dispersion in said aqueous liquid by continuous mechanical stirring or by continuous re-circulation with a pump of said liquid mixture in the several tanks containing said mixture, and, if necessary, by the addition of a surfactant and stabilizer chemical agent to aid in maintaining said uniform dispersion.
The injection rate of said reducing agent into said effluent gas stream being treated is at a mol flow rate that is at least one times greater than the mol flow rate of untreated gaseous sulfur dioxide in said effluent gas stream.
The injectors may be placed with their droplet outlet orifices into the hot gas flow being treated to a position at the outer edge of the combustion gas temperature zone, of about between 1700xc2x0 F. and 2200xc2x0 F., and where the droplets emerging from said injector or injectors are directed only into the entire gas flow region being treated at said temperature at which the efficient reaction of the chemical agent and the pollutant is favored, and where said injector droplet outlet orifices is moved either manually or by an automated control to remain at said outer temperature edge as said temperature edge changes due to changes in the boiler load.
The gas combustion temperature zone at which the said injectors are inserted may be determined by means of a thermocouple with a bare exposed tip that is inserted into said gas stream being treated, with said thermocouple tip being recessed within a ceramic tube where said ceramic tube is held in place in a hollow metal pipe, which is connected to a vacuum source that draws said hot gas into said ceramic tube to measure the gas temperature, and where said pipe is surrounded by an outer pair of pipes wherein flows cooling water to the end of said inner pipe containing the thermocouple wire and returns through the outer of said pair of cooling pipes.
The present invention may also include the steps of forming said aqueous mixture from a reducing agent in a powder form by delivering said reducing agent to said boiler or furnace by unloading said reducing agent from a supply tanker having bottom discharges suitable for discharge through a metering rotary valve or helical screw feeder to a pneumatic conveying eductor, with said eductor connected to a pipe conveying said chemical powder to a water tank, where said reducing agent is dispersed and mixed with water and maintained in uniform dispersion by continuous mechanical stirring, and, if necessary, by the addition of a chemical surfactant and stabilizer, and conveying said mixture by means of a submersible pump that maintains the prime to a high pressure centrifugal or progressive cavity pump to a second tank, with said second tank also containing a submersible pump that maintains a continuous prime to a high pressure liquid pump that re-circulates part of the flow to said second tank and feeds the balance of the aqueous mixture to said injector with said liquid and compressed air injection rates controlled by suitable flow meters, pressure gauges and valves.
The injector feed pipes to said injectors may each be cooled by an external, coaxial jacket pipe having flowing water, at a rate controlled by flow meters, pressure gauges and valves, and supplied by a gravity fed tank to maintain the cooling flow in the event of a power failure.
Still further, the invention may include the step of inserting said injector through pre-existing ports on said boiler or furnace.
The surfactant and stabilizer may be mixed in said aqueous mixture at concentration that are typically less than 1% by weight.
Hydraulic injectors may produce either a flat fan spray of a conical spray, depending on the boiler configuration and rating, are used in place of air atomized injectors.
Mechanical stirrers may preferably consist of one or more propellers placed at several locations along a shaft, with said propellers having an outer diameter that is at least one-third, and preferably more than one-half of the inner diameter of said tank containing said solid-liquid mixture, and with said shaft being rotated by a motor at a speed sufficient to induce high shear flow in said tanks.
The invention also includes small industrial boilers or furnaces where said liquid injectors are replaced by one or more externally insulated metal tubes containing said SO2 reducing agent, such as lime, in dry powder form, and where said reducing agent is transported pneumatically in said metal tubes to the high temperature gas region in the range of 1700xc2x0 F. to 2200xc2x0 F. being treated for SO2 removal, with the outlet of said tubes being inserted into the outer edge of the high temperature region of the boiler or furnace being treated.
The tubes may be placed coaxially with the flow direction of the gas being treated, with said tubes being equally spaced along a circle whose diameter is a large fraction of the diameter of the gas flow being treated, with the number of said tubes being selected so as to uniformly disperse said SO2 reducing agent throughout the gas volume being treated.
The present invention includes intermediate or large boilers or furnaces where the outlet a of said one or more pneumatic conveying tubes are flattened into a narrow ellipse so as to inject said dry SO2 reducing agent in a flat fan spray pattern that intercepts said gas flow being treated in a plane that is perpendicular to the hot gas flow direction in said boiler or furnace.
The invention also includes, in addition to said SO2 reducing agent dispersed in an aqueous mixture, a NOx reducing agent consisting of ammonia or urea or ammonia precursor is added to and dissolved in said mixture, with said NOx reducing agent being added at a concentration such that the mol flow rate of the NOx reducing agent into the furnace or boiler being treated is equal to or greater than the mol flow rate of the NOx species in the hot gas flow being treated. The NOx reducing agent concentration may be about a factor five to ten lower in concentration than that of the SO2 reducing agent.
The optimum placement of the several said injectors into furnaces or boilers of varying size can best be optimized by firing said furnaces or boilers with gas or oil or a low sulfur coal and adding sulfur powder through injection ports that are separate from the fuel injection ports in order to duplicate the higher SO2 concentrations that are encountered in regular and extended furnace or boiler operation.
Sulfur powder may be mixed uniformly with another fine combustible powder material such as fine sawdust or low sulfur pulverized coal at a mixture ratio such that the feed rate of the mixture is sufficiently high to result in a steady and uniform injection rate into the furnace being evaluated for SO2 reduction.
The high pressure, single or multi-stage centrifugal pump may be either attached to an electric motor of sufficient capacity to overcome the added power required to pump the higher viscosity aqueous lime mixture, or to an electric motor rated for operation with low viscosity water only that is driven by a variable alternating frequency electronic drive such that the motor speed is reduced to maintain the pump motor within its rated thermal limits.
The outer water-cooled pipe surrounding said aqueous mixture pipe may be eliminated and replaced with a ceramic insulating material and where further water is forced though said aqueous mixture pipe during insertion of said and removal of said injector in said boiler or furnace.
The startup and shutdown cooling water in said aqueous mixture pipe may be separated from said aqueous mixture flow by backflow check valve or by separate flow circuits to prevent the mixing of the two liquid flows.
The invention also includes a method whereby the optimization of the SO2 and NOx reduction in coal fired furnaces or boilers is implemented economically and at much reduced heat input by utilizing oil and/or gas co-fired with aqueous ammonia and sulfur powder or sulfur powder mixed with a combustible fuel, such as sawdust, to produce SO2 and NOx concentrations in said combustion gases that duplicate the concentrations with coal firing.
The simulation may be implemented in a cyclone combustor wherein the post-combustion zone is either in the downstream end of said cyclone combustor or immediately downstream of said cyclone combustor.
The present invention also includes a method in which a variable speed drive may be used control a direct current motor that is attached to a helical auger through which a powder or fine solid material is feed into a pneumatic feed duct, with said material flowing into said auger by means of a vibrator that is attached to the walls of the inverted V shaped box containing said powder or material.